The present disclosure relates to fluids and methods for use in subterranean treatment operations (e.g., fracturing operations).
Treatment fluids may be used in a variety of subterranean treatments. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The terms “treatment,” and “treating,” as used herein, do not imply any particular action by the fluid or any particular component thereof. One type of treatment used in the art to increase the conductivity of a subterranean formation is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid or a “pad fluid”) into a well bore that penetrates a subterranean formation at or above a sufficient hydraulic pressure to create or enhance one or more pathways, or “fractures,” in the subterranean formation. These fractures generally increase the permeability and/or conductivity of that portion of the formation. The fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the resultant fractures. The proppant particulates are thought to help prevent the fractures from fully closing upon the release of the hydraulic pressure, forming conductive channels through which fluids may flow to a well bore.
Maintaining sufficient viscosity in the treatment fluids used in these operations is important for a number of reasons. Maintaining sufficient viscosity is important in fracturing and sand control treatments for particulate transport and/or to create or enhance fracture width. Also, maintaining sufficient viscosity may be important in acidizing treatments, in friction reduction and to control and/or reduce fluid loss into the formation. To provide the desired viscosity, polymeric viscosifying agents commonly are added to the treatment fluids. These viscosifying agents, when hydrated and at a sufficient concentration, are capable of forming a viscous solution. However, certain polymeric viscosifying agents can lose their stability and/or their ability to viscosify the fluid above certain temperatures (e.g., the lower critical solution temperature). In brines and seawater, this temperature may be around 110° F.-120° F., due to high concentrations of ionic species (e.g., cationics like sodium, calcium, magnesium, potassium, and anionics like phosphates, nitrates sulfates, chlorides, carbonates) dissolved therein. Many treatment fluids are often subjected to temperatures of 100° F. or more during preparation, transportation, and/or use in a formation. Thus, these ionic species may hinder hydration of viscosifying agents in a brine and/or seawater, which may render a treatment fluid in those base fluids unstable or impractical for use.
While embodiments of this disclosure have been depicted and described and are defined by reference to example embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.